Texas Agrees on Questions for Mechanism to Meet Mandated Reserve Margin, Anderson Asks Whether Capacity Owners Should be Required to Divest Load Serving Entities

The Public Utility Commission of Texas has agreed on a series of questions to be issued for stakeholder comment regarding various options to meet a mandated reserve margin

The questions include those previously filed by Chairman Donna Nelson (click here for questions), and new questions from Commissioner Kenneth Anderson.

The Commission is to hold a technical session on responses to the questions on January 29-30.

Commissioner Brandy Marty said that no decisions would be made at that session, and suggested that another technical session in February would be appropriate.

Aside from general questions and those related to a centralized capacity market, Anderson's questions also sought comment on alternatives, such as Backstop Generation as an Ancillary Emergency Reserve Service in the Energy-Only Market, and a Reserve Margin Obligation on Load Serving Entities (LSEs).

Notably, in both the capacity market and LSE-obligation models, Anderson asked whether capacity owners should be forced to divest themselves of LSEs due to market power concerns.

For example, Anderson asked:

"To minimize capacity market manipulation, should generators participating in any capacity auction be required to divest themselves of any LSE? Should NOIEs be exempt from this obligation? Alternatively, is it sufficient to require non-NOIE generators to prove that they offer non-affiliated REPs bilateral contracts that are no less favorable than the terms that they offer their affiliated LSEs? Should they be required to offer more favorable terms to avoid market concentration problems?"

Other questions from Anderson include:

• What is the legal basis for adopting a resource adequacy mechanism? What restrictions exist on the Public Utility Commission of Texas' (PUCT) authority? Does the PUCT have the legal authority to implement any mandatory generation obligation outside of an energy-only market (EOM) construct?

• Does the PUCT have the authority to require municipal utilities and electric cooperatives to share the cost of any resource adequacy construct?

• How does the cost of paying all capacity a clearing price at the cost of incremental capacity compare to traditional utility rate of return regulation?

• How does pricing energy market revenues based on the market clearing price of energy compare to traditional utility fuel recovery?

• For a backstop procurement or in a capacity market, is it appropriate to price both capacity and energy based on a market clearing price?

• For a backstop procurement or in a capacity market, is it appropriate to pay the resources a market clearing price for energy if capacity payments guarantee return on and of capital?

• What extra capacity (in MW) would be required over and above the economic equilibrium reserve capacity provided by an energy-only market? How much would it cost for ERCOT to have that amount of capacity built?

• What is the cost of eliminating resource adequacy related outages per MWh under each of the following: (1) a capacity market; (2) EOM plus construction of state-owned generation; and (3) any other backstop or supplemental generation mechanism?

• Could new ancillary services be used to address resource adequacy?

• How do you ensure sufficient transparency so as to prevent affiliated generation and LSEs from exercising undue price influence in the market?

• What additional measures should be imposed to prevent market power abuse by large generators and independent power producer (IPP) generators that are affiliated with LSEs?

• How should the market be designed so as to avoid the problem of large incumbent IPPs keeping out small generators? Should the PUCT market power abuse rules be modified to lower the generation ownership limit to less than 10% of installed capacity?

• What performance requirements should be imposed on capacity bidders beyond an obligation to bid in the day ahead market (DAM)?